1. Field of the Invention
The present invention relates to a method and apparatus for estimating fluid flow. More specifically the present invention relates to methods and apparatus for evaluating fluid flow within a borehole.
2. Description of Related Art
The sampling of hydrocarbon producing wellbores, such as by well logging, can yield a litany of information useful in assessing the potential location and reserves of a given wellbore. The information may include permeability, porosity, bound fluid volume, formation pressure and temperature, and resistivity. Estimates of one or more of these borehole parameters in a specific formation can be made by sending signals from logging instruments inserted downhole. These parameters can also be determined by mechanically extracting fluids from within the formation. This can be done by a drill stem test or with an instrument that extracts fluids from the formations.
One example of a device that mechanically extracts fluid from within the formation is a formation test tool. Once inside of a borehole, a probe from the device is inserted past the mud cake to come in contact with the formation itself. Fluid is then withdrawn from the formation into the tool for subsequent sampling. After the sampling sequence, the formation pressure can be measured as it builds back up to its natural formation pressure. Models exist for estimating permeability based on the formation pressure and temperature tool data. These models may include a laminar or spherical model design. Examples of such devices can be found in the following references: U.S. Pat. No. 6,047,239, U.S. Pat. No. 5,2447,830, U.S. Pat. No. 5,949,060, and U.S. Pat. No. 4,745,802. Some drawbacks exist however with these formation test tools. Each sampling sequence requires that the sample point be at formation pressure. Since each sampling event necessarily reduces the pressure at the sample point, it may require from several minutes up to in excess of an hour to conduct subsequent sampling events.
Nuclear magnetic resonance (NMR) devices have also been utilized in estimating the formation permeability and/or fluid flow of the formation fluid. Generally, devices using NMR in well logging include a permanent magnet that generates a static magnetic field within the region of the formation to be investigated. Atomic nuclei contain magnetic moments associated with their nuclear spin. In the absence of an applied magnetic field, thermal fluctuations cause these moments to have random orientations in space. When these nuclei are subjected to a static magnetic field, the magnetic moments tend to align either parallel or anti-parallel to this applied field. The permanent magnet associated with the NMR devices orients the magnetic moments of the nuclei in the area being assessed. NMR devices also usually include a transmitter coil for inducing a radio frequency (RF) magnetic flux. The transmitter coil is typically oriented such that the magnetic field produced by the coil is substantially perpendicular to that of the static magnetic field. Also, a receiver coil for receiving reflected signals is included with the NMR tool.
In operation, the transmitter coil induces a RF magnetic pulse that reorients the magnetic moments of the nuclei along a direction that is perpendicular to both the direction of the static field of the permanent magnet and to the direction of the applied RF pulse. The pulse is maintained until the spin moments are perpendicular to the static field. Then the spins realign with the static magnetic field in a time period referred to as the spin-lattice relaxation rate T1. Moreover, the magnetic moments of the nuclei are out of alignment with the field produced by the permanent magnet. As such a perpendicular force is applied such that they precess around the region of the static field. The rate at which they precess is referred to as the Larmor frequency.
Theoretically, while precessing the spin vectors are generally aligned, however because the static field is inhomogeneous, the spins may precess at different rates. This in turn decays the different precession rates of the vector sum of the magnetization in the plane of the spins to zero. The decay rate, T2*, is typically referred to the free induction decay (FID). Another magnetic pulse with twice the duration of the first pulse can then be applied that flips the spin vectors 180°. The leading and lagging spins now switch position. Due to this phenomenon, the magnetization vectors can reconverge. Ultimately the spin vectors are realigned. Realignment creates a spin echo that is recordable by the receiver coil. Increasing the time between the excitation pulse and the realignment pulse is increased in turn decays the spin echo amplitude. The characteristic decay time (T2) is referred to as the spin-spin or transverse relaxation time. The amplitude of the spin echoes can be used to determine spin density, T1 and T2. The amplitudes of successive echoes decay with T2. Upon obtaining the T2 distributions, other formation characteristics, such as permeability, may be determined.
Typically T2 distributions are measured using an error-correcting step, such as a Carr-Purcell-Meiboom-Gill (CPMG) NMR pulse sequence. In order to provide meaningful results, the length of the recorded echo train must be at least as the maximum T2 of the spin system. During this time period, as well as during the preceding prepolarization period, the measurement is sensitive to displacements of the measuring device. Further, in some cases, the T2 distributions do not represent pore size distributions. Hydrocarbons in water wet rocks can change the correlation between T2 distribution and pore size distribution. Finally, the correlation between pore size distribution and permeability of the formation is achieved using several formulas based on large measured data sets, displaying relatively weak correlation. In carbonates, these formulae breakdown because of the formations' complex pore shapes.
Other types of flow meters are found in U.S. Pat. No. 6,755,086, and U.S. Pat. No. 6,601,461, and U.S. Pat. No. 4,901,018 (NMR), and U.S. Pat. No. 6,046,587. However, these NMR devices and methods developed heretofore, fail to provide an accurate means of evaluating fluid flow of formation fluid while downhole. Therefore, there exists the need for a method and device capable of being insertable into a borehole intersecting a hydrocarbon producing formation, and measuring fluid flow of fluid within the formation.